1. Technical Field
The present invention relates to equipment and methods used in testing the aspects of the cement-formation interface and quantifying the fluid influx through the interface between the formation and cement in a wellbore at a subterranean location.
2. Background Art
In the process of drilling and completing hydrocarbon wells, it is common place to install heavy steel casing in a well and to place cement between the casing and the well bore wall at a subterranean location to anchor the casing in place and prevent migration of fluids along the annulus outside the casing.
Cementing is a common well operation. For example, hydraulic cement compositions can be used in cementing operations in which a string of pipe, such as casing or liner, is cemented in a wellbore. Cementing materials used in wells comprise a slurry of Portland cement, water and sometimes one or more additives. Additives include accelerators (such as calcium chloride), weighting materials (such as barium sulfate), retarders (such as gypsum), light weight additives (such as bentonite), and a variety of lost-circulation materials (such as mica flakes). As used herein the term “cement slurry” refers to a mixture of cement and water in a form that can be pumped into the well to allow to set or hardened.
Cement used to stabilize the pipe in the wellbore and prevents undesirable migration of fluids along the annulus between the wellbore and the outside of the casing or liner between various zones of subterranean formations penetrated by the wellbore. Where the wellbore penetrates into a hydrocarbon-bearing zone of a subterranean formation, the casing can later be perforated to allow fluid communication between the zone and the wellbore. The cemented casing is intended to enable subsequent or remedial separation or isolation of one or more production zones of the wellbore, for example, by using downhole tools such as packers or plugs, or by using other techniques, such as forming sand plugs or placing cement in the perforations.
In performing cementing, a hydraulic cement composition is pumped as a fluid (typically in the form of suspension or slurry) into a desired location in the wellbore. For example, in cementing a casing or liner, the hydraulic cement composition is pumped into the annular space between the exterior surfaces of a pipe string and the borehole (that is, the wall of the wellbore). The cement composition is allowed time to set (harden) in the annular space, thereby forming an annular sheath of hardened, substantially impermeable cement. The hardened cement is provided to support and position the pipe string in the wellbore and to fill the annular space between the exterior surfaces of the pipe string and the borehole of the wellbore.
Poor bonding between the cement and the wellbore formation wall especially at the location of the hydrocarbon bearing formation can cause problems. Poor bonding with the formation material can be caused by a variety of reasons. As used herein the term “bond” as used in this context refers to the adhering or joining of the cement to the formation materials exposed in the wellbore wall. The area of contact between the cement and the formation material is referred to as the cement formation interface.
Poor nucleation causes the interaction between the cement particles themselves to be much higher than the interaction between the cement and the formation. This leads to very poor bonding of the cement with the formation.
If the well is in an underbalanced state prior to cementing, the exposed surface of the formation at the wellbore often has a thin layer of this formation fluid. The term “formation fluids” is used herein to refer to naturally occurring fluids present in the formation, such as, hydrocarbons, salt water, liquefied gases and other liquids. This layer of formation fluids interferes and has a detrimental effect on the bonding between the cement and the formation material and renders the combination incompatible.
Often HPHT (high pressure high temperature) wells (for example 350F. and 12,000 psi) require heavier cements that inherently have low water content. This sometimes causes low bonding because there is not sufficient water to keep the tensile stresses in the cement sheath under the threshold value to avoid deboning.
It is common for the wellbore to penetrate subterranean zones of formation materials, such as, shale. Shale, in the presence of freshwater expands, destabilizes and crumbles. This causes the formation at the interface to cave in leaving gaps or voids between the shale formation and cement. As used herein the “formation materials” refers to subterranean materials present at the wellbore wall.
Filter cake is often left behind on the formation at the wellbore. This filter cake remains in place after cementing and forms as a permeable layer between the cement and formation. This filter cake material forms a pathway for the fluid to migrate axially through the cement. This will also make the formation devoid of a strong chemical bond with the cement.
When Oil Based Drilling Fluids are used, incomplete surface cleaning with a surfactant-laden spacer either due to lack of sufficient shear rates, contact time or surfactant concentrations may leave a non-polar film that comes in between the cement and the wellbore surface.
The poor bond formation provides a path of low resistance for the formation fluid which is at a considerable high pressure to leak along the well bore between formations to zones. This prevents effective zonal isolation and build up pressure in the annulus of the wellbore.
There has been a long felt need in the industry for developing a method for characterizing the channeling of formation fluids through the interface between the setting cement and the formation. The challenge here is to quantify the fluid influx due to channeling during the entire process of setting of the cement through the cement-formation interface. In the present invention, an apparatus and characterization technique is designed to identify this process quantitatively.